Methods and systems for treating petroleum feedstock containing organic acids and sulfur

ABSTRACT

Methods and systems of treating petroleum feedstock contaminated with naphthenic acids and sulfur are disclosed. The methods and systems include heating the petroleum feedstock to decompose the naphthenic acids, pressurizing to minimize the portion in the vapor phase, sweeping water vapor and carbon dioxide into a headspace with a non-oxidizing gas, removing water vapor and carbon dioxide from the headspace, reacting the sulfur with an alkali metal and a radical capping gas to convert the sulfur into alkali sulfides, and removing the alkali sulfides. Also disclosed is reacting the naphthenic acid with water and an oxide or hydroxide of an alkaline earth element to convert the naphthenic acid into naphthenates, removing water, ketonizing, removing oxides or carbonates, reacting the sulfur with an alkali metal and a radical capping gas to convert the sulfur into alkali sulfides, and removing the alkali sulfides.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional PatentApplication Ser. No. 61/909,092 filed Nov. 26, 2013, entitled “Method toReduce Alkali Metal Needed for Desulfurization of High TAN PetroleumFeedstock.” The disclosure of the application to which the presentapplication claims priority is incorporated by reference.

Without claiming domestic priority, this application is related to U.S.Pat. No. 8,828,220 filed Nov. 1, 2010, titled “Upgrading of petroleumoil feedstocks using alkali metals and hydrocarbons” and U.S. Pat. No.8,828,221 filed Jul. 16, 2012, titled “Upgrading platform using alkalimetals.” These prior patent applications are expressly incorporatedherein by reference.

TECHNICAL FIELD

The present disclosure relates to methods and systems for treatingpetroleum feedstock containing organic acids and sulfur. Morespecifically, the present disclosure relates to reducing the amount ofalkali metal needed for desulfurization of high TAN petroleum feedstockby treating organic acids in high TAN petroleum feedstock prior todesulfurization.

BACKGROUND

There is an ongoing demand for hydrocarbon fuels as an energy source andnewer sources of hydrocarbon raw materials are being exploited. Thesenewer sources of hydrocarbon raw materials include shale oil, bitumen,heavy oils, and other similar materials. However, these types ofhydrocarbon raw materials often contain high levels ofdifficult-to-remove sulfur and heavy metals. The high level of nitrogen,sulfur, and heavy metals in these newer sources of hydrocarbon rawmaterials (which may collectively or individually be referred to as“petroleum feedstock”) makes processing these materials difficult.Typically, these petroleum feedstock materials are refined to remove thesulfur, nitrogen and heavy metals through processes known as“hydro-treating” or “alkali metal desulfurization.”

U.S. Pat. Nos. 8,828,820 and 8,828,821 to Gordon describe methods fordesulfurizing and demetallizing petroleum feedstock. Gordon describesmethods by which petroleum feedstock is reacted with molten alkali metalin the presence of a radical capping gas. In Gordon's process the moltenalkali metal reacts with heavy metals such as nickel and vanadium in thepetroleum feedstock. Alkali metal sulfides are also formed from sulfurin the petroleum feedstock. The treated heavy metals and alkali metalsulfides can then be separated from the oil by standard processes suchas gravimetric separation, filtration, or centrifugation.

However, these petroleum feedstocks that are high in sulfur and heavymetals can often be high in total acid number (TAN) with values in therange of 1 mg KOH/g. TAN is an important quality measurement of crudeoil and is a measurement of total acidity as determined by the amount ofpotassium hydroxide needed to neutralize the acids in one gram of oil.High TAN values can pose a corrosion problem to machinery, piping, orother metal surfaces that contact the high TAN petroleum. Due to thiscorrosion problem, petroleum refineries will often restrict the amountof high TAN petroleum feedstock that can be processed. Therefore, thereis a need to lower TAN levels in petroleum feedstock prior to refineryprocessing.

Generally, the acidity in high TAN petroleum feedstock can be attributedto organic acids, such as naphthenic acids. Havre describes naphthenicacids in petroleum feedstock as carboxylic monoacids of the generalformula RCOOH where R represents any cycloaliphatic structure. Havre, T.E. (2002). Formation of calcium naphthenate in water/oil systems,naphthenic acid chemistry and emulsion stability. Havre furtherdescribes naphthenic acids as C₁₀-C₅₀ compounds with 0-6 fused saturatedrings and with the carboxylic acid group attached to a ring via a shortside chain.

The method of Gordon can remove organic acids, including naphthenicacids, from petroleum feedstocks despite the varying specific structureof the organic acids. While much of the following discussion will referspecifically to naphthenic acids, it is understood that the disclosedmethods and systems may be used to treat other organic acids present inpetroleum feedstocks. In Gordon, the molten alkali metal can react withthe naphthenic acid and allow for their removal. In the case wheremolten sodium is the alkali metal added to petroleum feedstockcontaining naphthenic acids, the reaction of Equation 1a is assumed tooccur. A similar reaction where molten lithium is the alkali metal isdepicted in Equation 1b:

RCOOH+Na→RCOONa+½H₂  Equation 1a

RCOOH+Li→RCOOLi+½H₂  Equation 1b

In Equations 1a and 1b, the naphthenic acids are converted to sodiumnaphthenate and lithium naphthenate, respectively. The method of Gordoncan lower the TAN caused by naphthenic acids by converting thenaphthenic acids to naphthenate salts and thereby lowering thecorrosiveness of the treated petroleum feedstock. Unfortunately, thereare a number of drawbacks to using the method of Gordon or similarmethods to remove naphthenic acids from high TAN petroleum feedstocks.These drawbacks include the consumption of costly alkali metal in theprocess, the formation of amphiphilic alkali naphthenate salts that canform stable emulsions that can be difficult to remove, and the lack ofan easy methodology for recovering alkali metal from alkalinaphthenates.

One drawback to the method of Gordon and similar methods is that costlyalkali metal is consumed to convert naphthenic acids to alkalinaphthenates. Alkali metal that reacts with naphthenic acids is notavailable to react with and remove sulfur from the petroleum feedstock.Also, alkali naphthenates can be difficult to remove from the petroleumfeedstock. The amphiphilic nature of alkali naphthenates causes them toreside at water-oil interfaces and to form stable emulsions that can bedifficult to remove from the petroleum feedstock and create problemswith downstream processing. Furthermore, it is undesirable for thealkali metal (in the form of the alkali naphthenate) to remain in thepetroleum feedstock with amounts over about 100 ppm needing to beremoved. Lastly, it is difficult to regenerate the alkali metal fromalkali naphthenates. In contrast, alkali sulfide can be easily recoveredfrom the feedstock and the alkali metal from alkali sulfide can beregenerated via electrolysis.

Therefore, there is a need in the industry for new methods and systemsto treat naphthenic acids in high TAN petroleum feedstocks prior totreatment with alkali metal to remove sulfur and heavy metals. Suchmethods and systems are disclosed herein.

BRIEF SUMMARY

Methods and systems for treating petroleum feedstock are disclosed. Insome embodiments, the present application discloses methods and systemsfor treating petroleum feedstock comprising providing a petroleumfeedstock comprising organic acids, such as naphthenic acids, andsulfur, heating the petroleum feedstock to decompose the organic acids,pressurizing the petroleum feedstock to minimize a portion of thepetroleum feedstock in a vapor phase, sweeping water vapor and carbondioxide from the petroleum feedstock into a headspace with anon-oxidizing gas, removing water vapor and carbon dioxide from theheadspace to promote organic acid decomposition, reacting the sulfurwith an alkali metal and a radical capping gas to convert the sulfurinto alkali sulfides, and removing the alkali sulfides.

In other embodiments, the present application discloses methods andsystems for treating petroleum feedstock comprising providing apetroleum feedstock comprising organic acids, such as naphthenic acids,and sulfur, reacting the organic acid with a quantity of water and astoichiometric excess of an oxide or hydroxide of an alkaline earthelement while heating to convert the organic acid into alkaline earthcarboxylates, such as naphthenates, to generate an alkaline earthcarboxylate (naphthenate) mixture, removing water from the alkalineearth carboxylate (naphthenate) mixture to generate a dewatered mixture,reacting the sulfur in the dewatered mixture with an alkali metal and aradical capping gas to convert the sulfur into alkali sulfides, andremoving the alkali sulfides

In yet other embodiments, the present application discloses methods andsystems for treating petroleum feedstock comprising providing apetroleum feedstock comprising organic acids, such as naphthenic acids,and sulfur, reacting the organic acid with a quantity of water and astoichiometric excess of an oxide or hydroxide of an alkaline earthelement while heating to convert the organic acid into an alkaline earthcarboxylate (naphthenate) to generate an alkaline earth carboxylate(naphthenate) mixture, removing water from the alkaline earthcarboxylate (naphthenate) mixture to generate a dewatered mixture,heating the dewatered mixture to convert alkaline earth carboxylates(naphthenates) into ketones and alkaline earth oxides or alkaline earthcarbonates to generate a ketone mixture, removing alkaline earth oxidesor alkaline earth carbonates from the ketone mixture, reacting thesulfur in the ketone mixture with an alkali metal and a radical cappinggas to convert the sulfur into alkali sulfides, and removing the alkalisulfide.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to describe the manner in which the above-recited and otheradvantages and features of the invention can be obtained, a moreparticular description of the invention briefly described above will berendered by reference to specific embodiments thereof which areillustrated in the appended drawings. Understanding that these drawingsdepict only typical embodiments of the invention and are not thereforeto be considered to be limiting of its scope, the invention will bedescribed and explained with additional specificity and detail throughthe use of the accompanying drawings in which:

FIG. 1 illustrates a method and system for treating petroleum feedstockby decomposing naphthenic acid by heat followed by reaction with alkalimetal and radical capping gas;

FIG. 2 illustrates a method and system for treating petroleum feedstockby reacting the feedstock with oxides or hydroxides of alkaline earthelements followed by reaction with alkali metal and radical capping gas;

FIG. 3 illustrates a method and system for treating petroleum feedstockby reacting the feedstock with oxides or hydroxides of alkaline earthelements, dewatering, and ketonization, followed by reaction with alkalimetal and radical capping gas; and

FIG. 4 illustrates a method and system for treating petroleum feedstockby reacting the feedstock with oxides or hydroxides of alkaline earthelements, dewatering, followed by ketonization and reaction with alkalimetal and radical capping gas.

DETAILED DESCRIPTION OF THE INVENTION

The present application discloses methods and systems for treatingpetroleum feedstock. More specifically, the present disclosure relatesto treating organic acids (including naphthenic acids) in high TANpetroleum feedstock followed by treatment with alkali metals to removesulfur and optionally heavy metals. In some embodiments, the presentapplication discloses methods and systems for thermally treating aliquid high TAN petroleum feedstock at a temperature high enough and ata pressure sufficient to decompose carboxylic acid groups of the organicacids while minimizing any fraction of the feedstock from leaving theliquid phase. In other embodiments, the thermal pretreatment of thepetroleum feedstock can lower or eliminate the amount of organic ornaphthenic acids in the petroleum feedstock, thereby requiring lessalkali metal for further processing and lessening the amount ofnaphthenate salts that must be removed. In yet other embodiments, a highTAN petroleum feedstock can be pretreated with water and oxides orhydroxides of alkaline earth elements to generate alkaline earthcarboxylates or naphthenates before treatment with alkali metal fordesulfurization and demetallization. In some embodiments, high TANpetroleum feedstock can be pretreated with water and a stoichiometricexcess of oxides or hydroxides of alkaline earth elements to generatealkaline earth carboxylates or naphthenates, dewatered, heated to formketones, the ketones removed, and treated with alkali metal. In otherembodiments, the ketone formation and the alkali metal treatment can becarried out at the same time in a single reactor vessel. In yet otherembodiments, the alkali metals and/or the alkaline earth oxides orhydroxides can be regenerated.

In some embodiments the present application discloses methods andsystems for treating petroleum feedstock containing contaminants. Insome embodiments, contaminants can comprise one or more of organicacids, carboxylic acids, naphthenic acids, sulfur, or heavy metals. Insome embodiments, treating the petroleum feedstock can comprise removingone or more contaminants from the petroleum feedstock. In otherembodiments, treating the feedstock can comprise lowering the levels ofone or more contaminants to levels sufficient for further petroleumprocessing. In yet other embodiments, treating the petroleum feedstockcan comprise lowering the TAN values to sufficient levels to lessencorrosion during further processing of the petroleum feedstock.

In some embodiments, contaminants in petroleum feedstock can comprisesulfur, sulfur compounds and/or sulfur containing molecules andcomplexes. In other embodiments, sulfur contaminants can compriseorganic sulfur compounds, thiols, thiophenes, organic sulfides, and/ororganic disulfides. In yet other embodiments, sulfur contaminants caninclude benzothiophenes and dibenzothiophenes.

In some embodiments, heavy metal contaminants can comprise any metalthat interferes with any further processing or use of the petroleumfeedstock. In other embodiments, heavy metal contaminants can compriseheavy metals such as nickel and vanadium. In yet other embodiments,heavy metal contaminants can comprise iron, arsenic, and vanadium. Insome embodiments, heavy metal contaminants in petroleum feedstock cancomprise nickel, vanadium, copper, cadmium, lead, chromium, iron,cobalt, cadmium, zinc, and mercury.

In some embodiments petroleum feedstock can comprise high TAN petroleumfeedstock. In other embodiments, petroleum feedstock can comprise shaleoil, bitumen, heavy oils, heavy crudes, and other similar materials. Inyet other embodiments, petroleum feedstock can comprise shale oils suchas those found in the Green River Formation. In some embodiments,petroleum feedstock can comprise bitumens such as those found inAlberta, Canada. In other embodiments, petroleum feedstock can compriseheavy oils such as those found in Venezuela. In yet other embodiments,petroleum feedstock can comprise bitumens such as Athabasca bitumenfound in Northern Alberta, Canada.

In some embodiments, TAN values can comprise any substance in apetroleum feedstock that contributes to total acid number. In otherembodiments, organic acids in a petroleum feedstock contribute to TANvalues. In yet other embodiments, organic acids such as naphthenic acidsin petroleum feedstock contribute to TAN values. In other embodiments,TAN value is a measurement of acidity of a petroleum feedstock asdetermined by the amount of potassium hydroxide in milligrams that isneeded to neutralize the acids in one gram of the feedstock. In yetother embodiments, TAN value can be calculated by potentiometrictitration, color indicating titration, spectroscopic methods, orcombinations thereof. In some embodiments, TAN value can be calculatedby ASTM method D-664. In other embodiments, a high TAN value cancomprise values over 5. In yet other embodiments, a high TAN value cancomprise values over 3. In some embodiments, a high TAN value cancomprise values higher than 1.

In some embodiments, petroleum feedstock comprises organic acids. Inother embodiments, the organic acids in petroleum feedstock can comprisenaphthenic acids. In other embodiments, naphthenic acids can comprise anaphtha moiety with a carboxylic acid group. In yet other embodiments,naphthenic acids can comprise an unspecific mixture of carboxylic acidswith five or six membered carbon rings. In some embodiments, naphthenicacids can have a molecular weight between about 120 to over 700 a.m.u.In other embodiments, naphthenic acids can have a carbon backbone ofbetween about 9 to about 20 carbons. In yet other embodiments,naphthenic acids in petroleum feedstock can cause corrosion known asnaphthenic acid corrosion.

In some embodiments, naphthenic acids in petroleum feedstock can bedecomposed. In other embodiments, naphthenic acids can be decomposed byheating to generate a naphtha moiety, water and carbon dioxide. In yetother embodiments, naphthenic acids can be decomposed by heating underpressure to generate a naphtha moiety, water and carbon dioxide. In someembodiments, during heating, the pressure can be maintained to minimizethe portion of the petroleum feedstock that enters a vapor phase. Inother embodiments, during heating under pressure, a nonoxidizing gas cansweep the petroleum feedstock to draw away generated water and/or watervapor. In yet other embodiments, during heating under pressure, anonoxidizing gas can sweep the petroleum feedstock to draw awaygenerated carbon dioxide. In some embodiments, the generated waterand/or water vapor and/or carbon dioxide can be drawn into a headspace.In other embodiments, the generated water and/or water vapor and/orcarbon dioxide can be bled from the headspace to promote decompositionof the naphthenic acid. In yet other embodiments, the generated waterand/or water vapor and/or carbon dioxide can be bled from the headspaceto prevent inhibition of decomposition from a buildup of decompositionproducts.

In some embodiments, the nonoxidizing gas can comprise any inert gasthat does not react with the petroleum feedstock. In other embodiments,the nonoxidizing gas can comprise hydrogen, light hydrocarbon gas,pyrolysis gas, fuel gas, nitrogen, or combinations thereof. In yet otherembodiments, light hydrocarbon gas can comprise methane, ethane,propane, butane, pentane, hexane, or combinations thereof. In someembodiments, light hydrocarbon gas can comprise any hydrocarbon gascomprising between one and six carbons.

In some embodiments, naphthenic acids can be decomposed by heating thepetroleum feedstock in the range of a lower decomposition temperature ofabout 200° C. and an upper decomposition temperature of about 425° C. Inother embodiments, the range can comprise a lower decompositiontemperature of about 300° C. and an upper decomposition temperature ofabout 400° C. In yet other embodiments, the range can comprise a lowerdecomposition temperature of about 232° C. and an upper decompositiontemperature of about 400° C. In some embodiments, the range comprises alower decomposition temperature of about 260° C. and an upperdecomposition temperature of about 385° C. In other embodiments, thelower decomposition temperature can be 200° C., 210° C., 220° C., 230°C., 240° C., 250° C., 260° C., 270° C., 280° C., or 290° C. In yet otherembodiments, the upper decomposition temperature can be 350° C., 360°C., 370° C., 380° C., 390° C., 400° C., 410° C., 420° C., 430° C., 440°C., 450° C., 460° C., 470° C., 480° C., 490° C., or 500° C.

In some embodiments, naphthenic acids can be decomposed by heating thepetroleum feedstock under pressure in a pressure range of a lowerpressure limit of about one atmosphere and an upper pressure limit ofabout 1000 psig. In other embodiments, the pressure range can comprise alower pressure limit of about 15 psig and an upper pressure limit ofabout 500 psig. In yet other embodiments, the pressure range cancomprise a lower pressure limit of about 30 psig and an upper pressurelimit of about 300 psig. In some embodiments, the lower pressure limitcan be zero psig, 5 psig, 10 psig, 15 psig, 20 psig, 25 psig, or 30psig. In some embodiments, the upper pressure limit can be 300 psig, 400psig, 500 psig, 600 psig, 700 psig, 800 psig, 900 psig, or 1000 psig.

In some embodiments, naphthenic acids can react with alkaline earthoxides or hydroxides to generate alkaline earth naphthenates. In otherembodiments, naphthenic acids can react with water and a stoichiometricexcess of alkaline earth oxides or hydroxides under heating to generatealkaline earth naphthenates. Equations 2a-2b may describe this processwhere R is a naphtha group, R′ is another naphtha group, and Ae is analkaline earth element, and AeO is an alkaline earth oxide.

RCOOH+R′COOH+AeO→RCOOAeOOCR′.H₂O  Equation 2a

RCOOAeOOCR′.H₂O→RCOOAeOOCR′+H₂O  Equation 2b

In some embodiments, Equation 2a may describe the formation of amonohydrate salt of an alkaline earth naphthenate from naphthenic acidsand an alkaline earth oxide. In other embodiments, an alkaline earthhydroxide can take the place of the alkaline earth oxide. In yet otherembodiments, the alkaline earth naphthenate can comprise a coordinationcomplex of naphthenate groups complexed to the alkaline earth element.Equation 2b may describe the formation of an anhydrous salt of analkaline earth naphthenate from the monohydrate salt.

In some embodiments, naphthenic acids can react with water and astoichiometric excess of alkaline earth oxides or hydroxides to generatealkaline earth naphthenates by heating in the range of a lower reactiontemperature of about 80° C. and an upper reaction temperature of about95° C. In other embodiments, the range can comprise a lowerdecomposition temperature of about 50° C. and an upper decompositiontemperature of about 150° C. In yet other embodiments, the range cancomprise a lower reaction temperature of about 50° C. and an upperreaction temperature of about 400° C. In some embodiments, the lowerreaction temperature can be 50° C., 55° C., 60° C., 65° C., 70° C., 75°C., or 80° C. In other embodiments, the upper reaction temperature canbe 90° C., 95° C., 100° C., 105° C., 110° C., 115° C., 120° C., 125° C.,130° C., 135° C., 140° C., 145° C., 150° C., 155° C., 160° C., or 165°C.

In some embodiments, alkaline earth naphthenates can be heated togenerate ketones. Equations 2c-2d may describe this process where R is anaphtha group, R′ is another naphtha group, and Ae is an alkaline earthelement, AeO is an alkaline earth oxide, and AeCO₃ is an alkaline earthcarbonate:

RCOOAeOOCR′→RCOR′+AeCO₃  Equation 2c

RCOOAeOOCR′→RCOR′+AeO+CO₂  Equation 2d

Equation 2c may describe the formation of a ketone from the anhydroussalt of an alkaline earth naphthenate with an alkaline earth carbonatealso produced. In some embodiments, the ketone may be a ketonecomprising two naphtha moieties. Equation 2d may describe the formationof a ketone from the anhydrous salt of an alkaline earth naphthenatewith an alkaline earth oxide and carbon dioxide also produced. In otherembodiments, removal of the alkaline earth carbonate, alkaline earthoxide, and/or carbon dioxide can promote the ketonization reaction.

In some embodiments, alkaline earth naphthenates can be heated togenerate ketones in a range of a lower heating temperature of about 100°C. to an upper heating temperature of about 400° C. In otherembodiments, the range can comprise a lower heating temperature of about166° C. to an upper heating temperature of about 312° C. In someembodiments, the lower reaction temperature can be 100° C., 110° C.,120° C., 130° C., 140° C., 150° C., 160° C., 170° C., 180° C., 190° C.,or 200° C. In other embodiments, the upper reaction temperature can be290° C., 300° C., 305° C., 310° C., 320° C., 330° C., 340° C., 350° C.,360° C., 370° C., 380° C., 390° C., or 400° C.

In some embodiments, sulfur in the petroleum feedstock can be reactedwith an alkali metal and a radical capping gas to convert the sulfurinto alkali metal sulfides. In other embodiments, sulfur in thepetroleum feedstock can be reacted with an alkali metal and a radicalcapping gas with heating to convert the sulfur into alkali metalsulfides. In yet other embodiments, sulfur in the petroleum feedstockcan be reacted with an alkali metal and a radical capping gas to convertthe sulfur into alkali metal sulfides according to the methods disclosedin U.S. Pat. Nos. 8,828,820 and 8,828,821 to Gordon. Equation 3 maydescribe this process where S is a sulfur group, X is an first organicgroup, X′ is a second organic group, XSX′ is an organic sulfurcontaminant, H is a radical capping gas, and A is an alkali element.

XSX′+2A+H₂→A₂S+HX+HX′  Equation 3

In other embodiments, other reactions can describe reacting sulfur inpetroleum feedstock with an alkali metal and a radical capping gas toconvert the sulfur into alkali metal sulfides. In yet other embodiments,the alkali metal can be added in stoichiometric excess. In someembodiments, the radical capping gas can be added in stoichiometricexcess. In other embodiments, reacting sulfur in petroleum feedstockwith an alkali metal and a radical capping gas to convert the sulfurinto alkali metal sulfides can further comprise a catalyst to helppromote the reaction. The catalysts may include by way of non-limitingexample, molybdenum, nickel, cobalt or alloys of molybdenum, alloys ofnickel, alloys of cobalt, alloys of molybdenum containing nickel and/orcobalt, alloys of nickel containing cobalt and/or molybdenum, molybdenumoxide, nickel oxide or cobalt oxides and combinations thereof.

In some embodiments, reacting sulfur in petroleum feedstock with analkali metal and a radical capping gas to convert the sulfur into alkalimetal sulfides can be done with heating in the range of a lowerconversion temperature of about 150° C. and an upper conversiontemperature of about 450° C. In other embodiments, the range cancomprise a lower conversion temperature of about 200° C. and an upperconversion temperature of about 400° C. In yet other embodiments, thelower conversion temperature can be 150° C., 160° C., 170° C., 180° C.,190° C., or 200° C. In some embodiments, the upper conversiontemperature can be 400° C., 410° C., 420° C., 430° C., 440° C., 450° C.,460° C., 470° C., 480° C., 490° C., or 500° C. In other embodiments,reacting sulfur in petroleum feedstock with an alkali metal and aradical capping gas to convert the sulfur into alkali metal sulfides canbe carried out at a pressure greater than 250 psi. In yet otherembodiments, reacting sulfur in petroleum feedstock with an alkali metaland a radical capping gas to convert the sulfur into alkali metalsulfides can be carried out at a pressure below 2500 psi. In someembodiments, reacting sulfur in petroleum feedstock with an alkali metaland a radical capping gas to convert the sulfur into alkali metalsulfides can be carried out at a pressure between about 500 psi andabout 3000 psi.

In some embodiments, the alkali metal can comprise lithium, sodium, orpotassium, or combinations thereof. In other embodiments, the alkalimetal can comprise alloys of lithium, sodium, or potassium. In yet otherembodiments, the alkali metal may be molten to facilitate mixing withthe petroleum feedstock. In some embodiments, a powdered or other solidquantity of the alkali metal can be introduced to the petroleumfeedstock. Sodium is preferred alkali metal because of its low cost,ready availability, and ease of recovery and regeneration.

In some embodiments the radical capping gas can comprise a hydrocarbongas. In other embodiments, the radical capping gas can comprise hydrogengas. In yet other embodiments, radical capping gas can comprise methane,ethane, propane, butane, pentane, hexane, heptane, octane, ethene,propene, butene, pentene, hexene, heptane, octene, and their isomers. Insome embodiments, the radical capping gas can comprise otherhydrocarbons (such as octane, or other carbon containing compoundscontaining one or more carbon atoms). In other embodiments, the radicalcapping gas may comprise a mixture of hydrocarbon gases. In yet otherembodiments, the radical capping gas may comprise natural gas or shalegas—the gas produced by retorting oil shale. In some embodiments, theradical capping gas may comprise one or more of the following: methane,ethane, propane, butane, pentane, hexane, heptane, octane, ethene,propene, butene, pentene, hexene, heptene, octene, and isomers of theforegoing, natural gas, shale gas, liquid petroleum gas, ammonia,primary, secondary, and tertiary ammines, thiols, mercaptans, andhydrogen sulfide.

In some embodiments, alkali sulfide generated from the petroleumfeedstock can be processed to recover the elemental alkali metal andsulfur. In other embodiments, recovery of elemental alkali metal cancomprise an electrolytic reaction (electrolysis) of an alkali metalsulfide and/or polysulfide using an alkali ion conductive ceramicmembrane (such as, for example, a NaSICON or LiSICON membrane that iscommercially available from Ceramatec, Inc. of Salt Lake City, Utah). Insome embodiments, processes for recovering elemental alkali metal can befound in U.S. Pat. No. 3,787,315; U.S. Pat. No. 8,088,270; and U.S. Pat.No. 7,897,028 (which documents are incorporated herein by reference). Inyet other embodiments, the recovered elemental alkali metal can be usedto react with sulfur in the petroleum feedstock.

FIG. 1 illustrates a method 100 for treating petroleum feedstockcontaining contaminants. In some embodiments, a petroleum feedstockcontaining contaminants 102 can be transferred to a decompositionreactor 110. A non-oxidizing gas 112 can sweep the decomposition reactor110. The decomposition reactor 110 can be maintained at pressure tominimize an amount of the feedstock 102 that is in the vapor phase. Thedecomposition reactor 110 can be maintained at a temperature betweenabout 200° C. and 425° C. to decompose carboxylic acids. In someembodiments, the carboxylic acids can comprise naphthenic acids. Inother embodiments, the decomposition reactor can be maintained at atemperature between about 300° C. and 400° C. A gas induction impellercan draw the non-oxidizing gas 112 through the feedstock 102 to bubblethrough the feedstock to sweep water vapor and carbon dioxide into theheadspace. The headspace can be continuously bled 114 to maintain waterand carbon dioxide at levels that are favorable to carboxylic aciddecomposition. The treated feedstock 116 can be transferred to an alkalimetal reactor 120. In some embodiments, the temperature of thedecomposition reactor 110, the amount of non-oxidizing gas 112, theamount of pressure maintained, and the speed and/or capacity of the gasinduction impeller can be varied to generate effective decomposition ofcarboxylic acids. In other embodiments, the temperature of thedecomposition reactor 110, the amount of non-oxidizing gas 112, theamount of pressure maintained, and the speed and/or capacity of the gasinduction impeller can be varied to generate effective decomposition ofcarboxylic acids based on the viscosity of the petroleum feedstock, theTAN values, and/or the levels of contaminants.

In some embodiments, the treated feedstock 116 can be transferred to thealkali metal reactor 120 to be further treated. Radical capping gas 122and alkali metal 124 can be added to the alkali metal reactor 120. Inother embodiments, radical capping gas 122 can comprise one or more ofthe following: methane, ethane, propane, butane, pentane, hexane,heptane, octane, ethene, propene, butene, pentene, hexene, heptene,octene, and isomers of the foregoing, natural gas, shale gas, liquidpetroleum gas, ammonia, primary, secondary, and tertiary ammines,thiols, mercaptans, and hydrogen sulfide. In yet other embodiments,radical capping gas 122 can comprise any suitable gas material. In someembodiments, alkali metal 124 can comprise lithium, sodium, potassium,or combinations thereof. In other embodiments, the sulfur contaminantsin the treated feedstock 116 can form alkali sulfides in the alkalimetal reactor 120. In yet other embodiments, the heavy metalcontaminants in the treated feedstock 116 can be changed in oxidationstate to a reduced metallic state. The alkali metal treated feedstock126 can be transferred to a solid-liquid separator 130.

In some embodiments, the alkali metal treated feedstock can comprise oneor more of decomposed carboxylic acids (and/or decomposed naphthenicacids), alkali sulfides, and/or heavy metals in a reduced metallicstate. In other embodiments, one or more of the decomposed carboxylicacids (and/or decomposed naphthenic acids), alkali sulfides, and/orheavy metals in a reduced metallic state can be in a solid and/orprecipitated form. The solid-liquid separator 130 can separate solids132 from a liquid fraction 134. The liquid fraction 134 can betransferred for further processing 140. In some embodiments, thesolid-liquid separator 130 can comprise filtration, centrifugation,and/or hydrocyclonic separation. In other embodiments, the solid-liquidseparator 130 can comprise gravimetric separation methods.

In some embodiments, the solids 132 can be transferred to alkaliregeneration 136. The alkali regeneration 136 can comprise regeneratingthe alkali metal 124 from alkali sulfides or other alkali salts. Inother embodiments, alkali regeneration 136 can comprise regenerating thealkali metal 124 by an electrolytic process comprising an alkali ionconductive ceramic membrane. In yet other embodiments, alkaliregeneration 136 can comprise any method or process suitable forregenerating alkali metal from alkali sulfides or other alkali salts. Insome embodiments, regenerated alkali metal 128 can be transferred to thealkali metal 124 source for use in reactor 120.

FIG. 2 illustrates a method 200 for treating petroleum feedstockcontaining contaminants. In some embodiments, a petroleum feedstockcontaining contaminants 202 can be transferred to an alkaline earthreactor 210. A quantity of water 212 can be added to the alkaline earthreactor 210. A stoichiometric excess of an oxide or a hydroxide of analkaline earth element 214 can be added to the alkaline earth reactor210. The amount of water needed in the process can be determined byFourier Transform Infra Red analysis looking for when the carbonyl peakis no longer detected. This amount of water may be 1.5-5 times excessover the stoichiometric amount needed. It is understood that thealkaline earth oxide or hydroxide and water can be introduced into thereactor 210 as an aqueous solution or slurry. It is also understood thatless than stoichiometric excess of an oxide or a hydroxide of analkaline earth element 214 can be added to the alkaline earth reactor210 resulting in partial reduction in napthenic acid. In someembodiments, a mixture of alkaline earth oxides and alkaline earthhydroxides can be used. In other embodiments, alkaline earth oxides cancomprise magnesium oxide or calcium oxide. In yet other embodiments,alkaline earth hydroxides can comprise magnesium hydroxide or calciumhydroxide.

The alkaline earth reactor 210 can be maintained at a temperature tofacilitate the formation of alkaline earth naphthenates. In onenon-limiting embodiment, the temperature of the alkaline earth reactoris maintained between about 50° C. and 150° C. In other embodiments, thealkaline earth reactor 210 can be maintained at a temperature betweenabout 80° C. and 95° C. A mixer, an impellor, a stirrer or othersuitable device can be employed to facilitate formation of alkalineearth naphthenates in the alkaline earth reactor 210. In someembodiments, the temperature of the alkaline earth reactor 210, theamount of water 212 added, the amount of alkaline earth oxide, theamount of alkaline earth hydroxide, an amount of pressure maintained,and/or a speed and/or capacity of the mixer can be varied to generateeffective formation of alkaline earth naphthenates.

In some embodiments, the treated feedstock 216 can be transferred to adewatering reactor 220. The dewatering reactor 220 can separate adewatered treated feedstock 226 from a water fraction 222. Thedewatering reactor 220 can comprise any suitable process for separatinga dewatered treated feedstock 226 from a water fraction 222. In someembodiments, the dewatering reactor 220 can comprise an evaporator or anelectrostatic type dewatering process. In some embodiments, the waterfraction 222 can be recycled and returned to the alkaline earth reactor210.

In some embodiments, the dewatered treated feedstock 226 can betransferred to an alkali metal reactor 230 to be further treated.Radical capping gas 232 and alkali metal 234 can be added to the alkalimetal reactor 230. In other embodiments, radical capping gas 232 cancomprise one or more of the following: methane, ethane, propane, butane,pentane, hexane, heptane, octane, ethene, propene, butene, pentene,hexene, heptene, octene, and isomers of the foregoing, natural gas,shale gas, liquid petroleum gas, ammonia, primary, secondary, andtertiary ammines, thiols, mercaptans, and hydrogen sulfide. In yet otherembodiments, radical capping gas 232 can comprise any suitable gasmaterial. In some embodiments, alkali metal 234 can comprise lithium,sodium, potassium, or combinations thereof. In other embodiments, thesulfur contaminants in the dewatered treated feedstock 226 can formalkali sulfides in the alkali metal reactor 230. In yet otherembodiments, the heavy metal contaminants in the dewatered treatedfeedstock 226 can be changed in oxidation state to a reduced metallicstate. In other embodiments, alkaline earth naphthenates in thedewatered feedstock 226 can form ketones upon heating. In someembodiments, reacting sulfur in petroleum feedstock with an alkali metaland a radical capping gas to convert the sulfur into alkali metalsulfides can be done with heating in the range of about 150° C. to about450° C. In other embodiments, the temperature can range from about 200°C. to about 400° C. The alkali metal treated feedstock 236 can betransferred to a solid-liquid separator 240.

In some embodiments, the alkali metal treated feedstock can comprise oneor more of alkaline earth naphthenates (and/or naphthenate salts),alkaline earth carbonates, alkali sulfides, and/or heavy metals in areduced metallic state. In other embodiments, one or more of thealkaline earth naphthenates (and/or naphthenate salts), alkali sulfides,and/or heavy metals in a reduced metallic state can be in a solid and/orprecipitated form. The solid-liquid separator 240 can separate solids242 from a liquid fraction 246. The liquid fraction 246 can betransferred for further processing 250. In some embodiments, thesolid-liquid separator 240 can comprise filtration, centrifugation,and/or hydrocyclonic separation. In other embodiments, the solid-liquidseparator 240 can comprise gravimetric separation methods.

In some embodiments, the solids 244 can be transferred to regenerationcell 246. The regeneration cell 246 can comprise equipment to regeneratethe alkali metal 234 from alkali sulfides or other alkali salts. Inother embodiments, regeneration cell 246 can comprise an electrolyticprocess to regenerate the alkali metal 234 comprising an alkali ionconductive ceramic membrane. In yet other embodiments, regeneration cell246 can comprise any method or process suitable for regenerating alkalimetal 234 from alkali sulfides or other alkali salts. In someembodiments, regenerated alkali metal 248 can be transferred to thealkali metal 234 source for use in reactor 230.

In other embodiments, alkaline earth carbonates can be regenerated toform alkaline earth oxides or alkaline earth hydroxides. In yet otherembodiments, alkaline earth carbonates can be regenerated to formalkaline earth oxides by heating the alkaline earth carbonates inregeneration cell 246. In some embodiments, regenerated alkaline earthoxides and/or alkaline earth hydroxides can be returned 249 to thealkaline earth reactor 210. In other embodiments, if the alkali metal234 comprises sodium then the alkaline earth element comprises analkaline earth metal that is not reduced by sodium, such as calcium. Insuch cases, magnesium would not be preferred because it is reduced bysodium.

FIG. 3 illustrates a method and system 300 for treating petroleumfeedstock containing contaminants. In some embodiments, a petroleumfeedstock containing contaminants 302 can be transferred to an alkalineearth reactor 310. A stoichiometric excess of an oxide or a hydroxide ofan alkaline earth element 312 in a water solution or slurry can be addedto the alkaline earth reactor 310. In some embodiments, a mixture ofalkaline earth oxides and alkaline earth hydroxides can be used. Inother embodiments, alkaline earth oxides can comprise magnesium oxide orcalcium oxide. In yet other embodiments, alkaline earth hydroxides cancomprise magnesium hydroxide or calcium hydroxide. A quantity of water314 can be added to the alkaline earth reactor 310. It is understoodthat the alkaline earth oxide or hydroxide and water can be introducedinto the reactor 310 as an aqueous solution or slurry. It is alsounderstood that less than stoichiometric excess of an oxide or ahydroxide of an alkaline earth element 312 can be added to the alkalineearth reactor 310 resulting in partial reduction in napthenic acid

The alkaline earth reactor 310 can be maintained at a temperaturebetween about 50° C. and 150° C. to facilitate the formation of alkalineearth naphthenates. In other embodiments, the alkaline earth reactor canbe maintained at a temperature between about 80° C. and 95° C. A mixer,stirrer or other suitable device can be employed to facilitate formationof alkaline earth naphthenates in the alkaline earth reactor 310. Insome embodiments, the temperature of the alkaline earth reactor 310, theamount of water 314 added, the amount of alkaline earth oxide, theamount of alkaline earth hydroxide, an amount of pressure maintained,and/or a speed and/or capacity of the mixer can be varied to generateeffective formation of alkaline earth naphthenates.

In some embodiments, a treated feedstock from the alkaline earth reactor310 can be transferred to a dewatering reactor 320. The dewateringreactor 320 can separate a dewatered treated feedstock from a waterfraction 322. In other embodiments, the dewatering reactor 320 cancomprise any suitable process for separating a dewatered treatedfeedstock from a water fraction 322. In some embodiments, the dewateringreactor 320 can comprise an evaporator or an electrostatic typedewatering process. In yet other embodiments, the water fraction 322 canbe recycled and returned to the alkaline earth reactor 310.

In some embodiments, the dewatered treated feedstock can be transferredto a ketonization reactor 330. The ketonization reactor 330 can bemaintained at a temperature between about 100° C. and 400° C. tofacilitate decomposition of alkaline earth naphthenates to form ketonesand alkaline earth oxides and/or alkaline earth carbonates. In otherembodiments, the alkaline earth reactor 310 can be maintained at atemperature between about 166° C. and about 312° C. In some embodiments,alkaline earth naphthenates can react in the ketonization reactor 330 toform ketones and/or ketones of naphthenates. A mixer, stirrer or othersuitable device can be employed to facilitate formation of ketones inthe ketonization reactor 330. In some embodiments, a temperature of theketonization reactor 330, an amount of pressure maintained, and/or aspeed and/or capacity of the mixer can be varied to generate effectiveformation of ketones.

In some embodiments, the feedstock from the ketonization reactor 330 canbe transferred to a first solid-liquid separator 340. In otherembodiments, the feedstock from the ketonization reactor 330 cancomprise ketones, alkaline earth oxides, and/or alkaline earthcarbonates. In yet other embodiments, some or all of the ketones,alkaline earth oxides, and/or alkaline earth carbonates can be in asolid and/or precipitated form. The first solid-liquid separator 340 canseparate first solids 342 from a first liquid fraction. In someembodiments, the solid-liquid separator 340 can comprise filtration,centrifugation, and/or hydrocyclonic separation. In other embodiments,the solid-liquid separator 340 can comprise gravimetric separationmethods.

In some embodiments, the first solids 342 can comprise alkaline earthcarbonates, alkaline earth oxides or alkaline earth hydroxides. In someembodiments, alkaline earth carbonates can undergo thermal decompositionto form alkaline earth oxides and carbon dioxide. In yet otherembodiments, alkaline earth carbonates can be regenerated to formalkaline earth oxides by heating the alkaline earth carbonates as partof a regeneration process. In some embodiments, regenerated alkalineearth oxides and/or alkaline earth hydroxides can be returned to thealkaline earth reactor 310.

In some embodiments, the first liquid fraction can be transferred to analkali metal reactor 350 to be further treated. Radical capping gas 352and alkali metal 354 can be added to the alkali metal reactor 350. Inother embodiments, radical capping gas 352 can comprise one or more ofthe following: methane, ethane, propane, butane, pentane, hexane,heptane, octane, ethene, propene, butene, pentene, hexene, heptene,octene, and isomers of the foregoing, natural gas, shale gas, liquidpetroleum gas, ammonia, primary, secondary, and tertiary ammines,thiols, mercaptans, and hydrogen sulfide. In yet other embodiments,radical capping gas 352 can comprise any suitable gas material. In someembodiments, alkali metal 354 can comprise lithium, sodium, potassium,or combinations thereof. In other embodiments, the sulfur contaminantsin the first liquid fraction can form alkali sulfides in the alkalimetal reactor 350. In yet other embodiments, the heavy metalcontaminants in the first liquid fraction can be changed in oxidationstate to a reduced metallic state. After reacting in the alkali metalreactor, the alkali metal treated feedstock can be transferred to asecond solid-liquid separator 360.

In some embodiments, the alkali metal treated feedstock can comprise oneor more of alkali sulfides and optionally heavy metals in a reducedmetallic state. In yet other embodiments, one or more of the alkalisulfides and heavy metals in a reduced metallic state can be in a solidand/or precipitated form. The second solid-liquid separator 360 canseparate second solids from a second liquid fraction. The second liquidfraction can be transferred for further processing 370. In someembodiments, the solid-liquid separator 360 can comprise filtration,centrifugation, and/or hydrocyclonic separation. In other embodiments,the solid-liquid separator 360 can comprise gravimetric separationmethods.

In some embodiments, the second solids can be transferred toregeneration cell 362. The regeneration cell 362 can comprise equipmentto regenerate the alkali metal 354 from alkali sulfides or other alkalisalts. In other embodiments, regeneration cell 362 can comprise anelectrolytic process to regenerate the alkali metal 354 comprising analkali ion conductive ceramic membrane. In yet other embodiments,regeneration cell 362 can comprise any method or process suitable forregenerating alkali metal 354 from alkali sulfides or other alkalisalts. In some embodiments, regenerated alkali metal 354 can be returnedto the alkali metal reactor 350. In other embodiments, if the alkalimetal 354 comprises sodium then the alkaline earth element comprises analkaline earth metal that is not reduced by sodium, such as calcium. Insuch cases, magnesium would not be preferred because it is reduced bysodium.

FIG. 4 illustrates a method and systems 400 for treating petroleumfeedstock containing contaminants. In some embodiments, a petroleumfeedstock containing contaminants 402 can be transferred to an alkalineearth reactor 410. A stoichiometric excess of an oxide or a hydroxide ofan alkaline earth element 412 can be added to the alkaline earth reactor410. In some embodiments, a mixture of alkaline earth oxides andalkaline earth hydroxides can be used. In other embodiments, alkalineearth oxides can comprise magnesium oxide or calcium oxide. In yet otherembodiments, alkaline earth hydroxides can comprise magnesium hydroxideor calcium hydroxide. A quantity of water 414 can be added to thealkaline earth reactor 410. It is understood that the alkaline earthoxide or hydroxide and water can be introduced into the reactor 410 asan aqueous solution or slurry. It is also understood that less thanstoichiometric excess of an oxide or a hydroxide of an alkaline earthelement 412 can be added to the alkaline earth reactor 410 resulting inpartial reduction in napthenic acid

The alkaline earth reactor 410 can be maintained at a temperaturebetween about 50° C. and 150° C. to facilitate the formation of alkalineearth naphthenates. In other embodiments, the alkaline earth reactor 410can be maintained at a temperature between about 80° C. and 95° C. Amixer, stirrer or other suitable device can be employed to facilitateformation of alkaline earth naphthenates in the alkaline earth reactor410. In some embodiments, the temperature of the alkaline earth reactor410, the amount of water 414 added, the amount of alkaline earth oxide,the amount of alkaline earth hydroxide, an amount of pressuremaintained, and/or a speed and/or capacity of the mixer can be varied togenerate effective formation of alkaline earth naphthenates.

In some embodiments, a treated feedstock from the alkaline earth reactor410 can be transferred to a dewatering reactor 420. The dewateringreactor 420 can separate a dewatered treated feedstock from a waterfraction 422. In some embodiments, the dewatering reactor 420 cancomprise an evaporator or an electrostatic type dewatering process. Inother embodiments, the dewatering reactor 420 can comprise any suitableprocess for separating a dewatered treated feedstock from a waterfraction 422. In yet other embodiments, the water fraction 422 can bereturned to the alkaline earth reactor 410.

In some embodiments, the dewatered treated feedstock can be transferredto an alkali metal reactor 430 to be further treated. Radical cappinggas 432 and alkali metal 434 can be added to the alkali metal reactor430. In other embodiments, radical capping gas 432 can comprise one ormore of the following: methane, ethane, propane, butane, pentane,hexane, heptane, octane, ethene, propene, butene, pentene, hexene,heptene, octene, and isomers of the foregoing, natural gas, shale gas,liquid petroleum gas, ammonia, primary, secondary, and tertiary ammines,thiols, mercaptans, and hydrogen sulfide. In yet other embodiments,radical capping gas 432 can comprise any suitable gas material. In someembodiments, alkali metal 434 can comprise lithium, sodium, potassium,or combinations thereof. In other embodiments, sulfur contaminants inthe dewatered treated feedstock can form alkali sulfides in the alkalimetal reactor 430. In yet other embodiments, heavy metal contaminants inthe dewatered treated feedstock can be changed in oxidation state to areduced metallic state. In some embodiments, alkaline earth naphthenatescan react in the alkali metal reactor 430 to form ketones and/or ketonesof naphthenates.

The alkali metal reactor 430 can be maintained at a temperature betweenabout 100° C. and 400° C. to facilitate decomposition of alkaline earthnaphthenates to form ketones and alkaline earth oxides and/or alkalineearth carbonates. In other embodiments, the alkali metal reactor 430 canbe maintained at a temperature between about 166° C. and about 312° C.In yet other embodiments, the alkali metal reactor can first be heatedto a temperature range to promote ketonization of the alkaline earthnaphthenates and then subsequently heated to a temperature range topromote formation of alkali sulfides. In some embodiments, a temperaturerange can be selected to promote ketonization of the alkaline earthnaphthenates and formation of alkali sulfides.

After reacting in the alkali metal reactor, the alkali metal treatedfeedstock can be transferred to a solid-liquid separator 440. In someembodiments, the alkali metal treated feedstock can comprise one or moreof ketones, alkaline earth naphthenates (and/or naphthenate salts),alkaline earth oxides, alkaline earth carbonates, alkali sulfides,and/or heavy metals in a reduced metallic state. In other embodiments,the alkali metal treated feedstock can comprise ketones, alkali sulfidesand/or heavy metals in a reduced metallic state. In yet otherembodiments, one or more of the alkali sulfides and/or heavy metals in areduced metallic state can be in a solid and/or precipitated form. Thesolid-liquid separator 440 can separate solids from a liquid fraction.The liquid fraction can be transferred for further processing 450. Insome embodiments, the solid-liquid separator 440 can comprisefiltration, centrifugation, and/or hydrocyclonic separation. In otherembodiments, the solid-liquid separator 440 can comprise gravimetricseparation methods.

In some embodiments, the solids can be transferred to regeneration cell442. The regeneration cell 442 can comprise equipment to regenerate thealkali metal 434 from alkali sulfides or other alkali salts. In otherembodiments, regeneration cell 442 can comprise an electrolytic processto regenerate the alkali metal 434 comprising an alkali ion conductiveceramic membrane. In yet other embodiments, regeneration cell 442 cancomprise any method or process suitable for regenerating alkali metalfrom alkali sulfides or other alkali salts. In some embodiments,regenerated alkali metal can be transferred to the alkali metal 434source for use in the alkali metal reactor 430. In other embodiments, ifthe alkali metal 434 comprises sodium then the alkaline earth elementcomprises an alkaline earth metal that is not reduced by sodium, such ascalcium. In such cases, magnesium would not be preferred because it isreduced by sodium.

In yet other embodiments, the solids can comprise alkaline earth oxidesor alkaline earth hydroxides. In some embodiments, alkaline earthcarbonates can be regenerated to form alkaline earth oxides or alkalineearth hydroxides. In yet other embodiments, alkaline earth carbonatescan be regenerated to form alkaline earth oxides by heating the alkalineearth carbonates as part of a regeneration process in regeneration cell442. In some embodiments, regenerated alkaline earth oxides and/oralkaline earth hydroxides can be returned to the alkaline earth reactor410.

The terms “a,” “an,” “the” and similar referents used in the context ofdescribing the invention (especially in the context of the followingclaims) are to be construed to cover both the singular and the plural,unless otherwise indicated herein or clearly contradicted by context.Recitation of ranges of values herein is merely intended to serve as ashorthand method of referring individually to each separate valuefalling within the range. Unless otherwise indicated herein, eachindividual value is incorporated into the specification as if it wereindividually recited herein. All methods described herein can beperformed in any suitable order unless otherwise indicated herein orotherwise clearly contradicted by context. The use of any and allexamples, or exemplary language (e.g., “such as”) provided herein isintended merely to better illuminate the invention and does not pose alimitation on the scope of the invention otherwise claimed. No languagein the specification should be construed as indicating any non-claimedelement essential to the practice of the invention.

It is contemplated that numerical values, as well as other values thatare recited herein are modified by the term “about”, whether expresslystated or inherently derived by the discussion of the presentdisclosure. As used herein, the term “about” defines the numericalboundaries of the modified values so as to include, but not be limitedto, tolerances and values up to, and including the numerical value somodified. That is, numerical values can include the actual value that isexpressly stated, as well as other values that are, or can be, thedecimal, fractional, or other multiple of the actual value indicated,and/or described in the disclosure.

Groupings of alternative elements or embodiments of the inventiondisclosed herein are not to be construed as limitations. Each groupmember may be referred to and claimed individually or in any combinationwith other members of the group or other elements found herein. It isanticipated that one or more members of a group may be included in, ordeleted from, a group for reasons of convenience and/or patentability.When any such inclusion or deletion occurs, the specification is deemedto contain the group as modified thus fulfilling the written descriptionof all Markush groups used in the appended claims.

Certain embodiments of this invention are described herein, includingthe best mode known to the inventors for carrying out the invention. Ofcourse, variations on these described embodiments will become apparentto those of ordinary skill in the art upon reading the foregoingdescription. The inventor expects skilled artisans to employ suchvariations as appropriate, and the inventors intend for the invention tobe practiced otherwise than specifically described herein. Accordingly,this invention includes all modifications and equivalents of the subjectmatter recited in the claims appended hereto as permitted by applicablelaw. Moreover, any combination of the above-described elements in allpossible variations thereof is encompassed by the invention unlessotherwise indicated herein or otherwise clearly contradicted by context.

It is to be understood that the embodiments of the invention disclosedherein are illustrative of the principles of the present invention.Other modifications that may be employed are within the scope of theinvention. Thus, by way of example, but not of limitation, alternativeconfigurations of the present invention may be utilized in accordancewith the teachings herein. Accordingly, the present invention is notlimited to that precisely as shown and described.

1. A method for treating petroleum feedstock comprising: providing apetroleum feedstock comprising naphthenic acids and sulfur; heating thepetroleum feedstock to decompose the naphthenic acids; pressurizing thepetroleum feedstock to minimize a portion of the petroleum feedstock ina vapor phase; sweeping water vapor and carbon dioxide from thepetroleum feedstock into a headspace with a non-oxidizing gas; removingwater vapor and carbon dioxide from the headspace to promote naphthenicacid decomposition; reacting the sulfur with an alkali metal and aradical capping gas to convert the sulfur into alkali sulfides; andremoving the alkali sulfide.
 2. The method of claim 1, wherein thepetroleum feedstock is heated in a range of about 200° C. to about 425°C.
 3. The method of claim 1, wherein the petroleum feedstock is heatedin a range of about 300° C. to about 400° C.
 4. The method of claim 1,wherein the non-oxidizing gas comprises hydrogen, light hydrocarbon gas,pyrolysis gas, or combinations thereof.
 5. The method of claim 1,wherein the alkali metal comprises lithium, sodium, potassium, orcombinations thereof.
 6. The method of claim 1, wherein the radicalcapping gas comprises one or more of the following: methane, ethane,propane, butane, pentane, hexane, heptane, octane, ethene, propene,butane, pentene, hexene, heptene, octene, and isomers of the foregoing,natural gas, shale gas, liquid petroleum gas, ammonia, primary,secondary, and tertiary ammines, thiols, mercaptans, and hydrogensulfide.
 7. The method of claim 1, further comprising regenerating thealkali metal from the alkali metal sulfide.
 8. The method of claim 7,wherein regenerating the alkali metal from the solids comprises anelectrolytic process using an alkali metal ion conductive ceramicmembrane.
 9. A method for treating petroleum feedstock comprising:providing a petroleum feedstock comprising naphthenic acids and sulfur;reacting the naphthenic acid an aqueous solution or slurry containing anoxide or hydroxide of an alkaline earth element while heating to convertthe naphthenic acid into alkaline earth naphthenates, thereby generatingan alkaline earth naphthenate mixture; removing water from the alkalineearth naphthenate mixture to generate a dewatered mixture; reacting thesulfur in the dewatered mixture with an alkali metal and a radicalcapping gas to convert the sulfur into alkali sulfides; and removing thealkali sulfides.
 10. The method of claim 9, wherein the alkaline earthmixture is heated in a range of about 80° C. to about 95° C.
 11. Themethod of claim 9, wherein the dewatered mixture is heated in a range ofabout 300° C. to about 400° C.
 12. The method of claim 9, wherein thealkali metal comprises sodium and the alkaline earth element comprisesone or more of calcium, strontium, or barium.
 13. The method of claim 9,further comprising regenerating the alkali metal from the alkali metalsulfide.
 14. The method of claim 7, wherein regenerating the alkalimetal from the solids comprises an electrolytic process using an alkalimetal ion conductive ceramic membrane.
 15. A method for treatingpetroleum feedstock comprising: providing a petroleum feedstockcomprising naphthenic acids and sulfur; reacting the naphthenic acidwith an aqueous solution or slurry containing an oxide or hydroxide ofan alkaline earth element while heating to convert the naphthenic acidinto an alkaline earth naphthenate, thereby generating an alkaline earthnaphthenate mixture; removing water from the alkaline earth naphthenatemixture to generate a dewatered mixture; heating the dewatered mixtureto convert alkaline earth naphthenates into ketones and alkaline earthoxides or alkaline earth carbonates, thereby generating a ketonemixture; removing alkaline earth oxides or alkaline earth carbonatesfrom the ketone mixture; reacting the sulfur in the ketone mixture withan alkali metal and a radical capping gas to convert the sulfur intoalkali sulfides; and removing the alkali sulfide.
 16. The method ofclaim 15, wherein the dewatered mixture is heated in a range of about166° C. to about 312° C.
 17. The method of claim 15, wherein heating thedewatered mixture to convert alkaline earth naphthenates into ketonesand alkaline earth oxides or alkaline earth carbonates and reacting thesulfur with an alkali metal and a radical capping gas to convert thesulfur into an alkali sulfide is carried out at the same time in asingle reaction vessel.
 18. The method of claim 17, wherein the alkalimetal comprises sodium and the alkaline earth element comprises one ormore of calcium, strontium, or barium.
 19. The method of claim 15,further comprising regenerating the alkaline earth carbonates with heatto form alkaline earth oxides.
 20. The method of claim 15, whereinremoving the alkaline earth oxides or alkaline earth carbonates and thealkali sulfide comprises filtration, centrifugation, hydrocyclonicseparation, or combinations thereof.